Q4 2016 production of 51.9 Mboe/d (73% oil), up 16% over Q3 2016 and 38% year over year

Full year 2016 production of 43.0 Mboe/d (73% oil), up 30% year over year

Q4 2016 average realized prices were $46.72 per barrel of oil, $2.53 per Mcf of natural gas and $17.70 per barrel of natural gas liquids, resulting in a total equivalent price of $38.72/boe, up 13% from the Q3 2016 total equivalent price of $34.39/boe

Q4 2016 cash operating costs of $8.48/boe, including LOE of $4.89/boe and cash G&A of $0.92/boe

Proved reserves as of December 31, 2016 of 205.5 MMboe
(68% oil), up 31% year over year; proved developed finding and development ("PD F&D") costs of $7.26/boe

Previously announced pending acquisition of Brigham Resources expected to close at the end of February 2017

Increasing pro forma full year 2017 production guidance to 69.0 to 76.0 Mboe/d, up from 64.0 to 73.0 Mboe/d

Operating six horizontal rigs, including first operated rig in the Southern Delaware Basin, with plans to add two additional rigs after the closing of the pending Brigham Resources acquisition

"Diamondback achieved over 40% production growth in the second half of 2016 by showcasing our ability to respond quickly to a rising commodity price environment. We ended the year operating five rigs, and as I said in November, we are just beginning to bear the fruit of our
activity ramp. We recently added a sixth operated rig, our first in the Southern Delaware Basin, and plan to add two more rigs to the Delaware Basin following the closing of the pending Brigham transaction at the end of February," stated Travis Stice, Chief Executive Officer of Diamondback.

Mr. Stice continued, "After doubling our Tier 1 acreage in the second half of 2016, our focus now shifts to execution. Diamondback's success has and continues to be driven by our ability to identify accretive opportunities, integrate these efficiently into operations and convert resource into cash flow. Our resource expansion into the Southern Delaware Basin marks another opportunity to expand our operational leadership in regards to low cost operations, best in class well
productivity and, above all, creating shareholder value. Our updated 2017 guidance implies over 65% production growth at the midpoint, while conservatively preparing for potential service cost inflation with respect to capital guidance. Our pro forma balanced footprint secures Diamondback's ability to generate leading growth rates within cash flow for years to come."

OPERATIONAL HIGHLIGHTS

Diamondback's Q4 2016 production was 51.9 Mboe/d (73% oil), up 38% year over year from 37.6 Mboe/d in Q4 2015, and up 16% quarter over quarter from 44.9 Mboe/d in Q3 2016. Average daily production for the full year 2016 was 43.0 Mboe/d (73% oil), exceeding the high end of its guidance range of 41.0 to 42.0 Mboe/d and up 30% year over year from
33.1 Mboe/d in 2015.

During the fourth quarter of 2016, Diamondback averaged five operated rigs, drilled 25 gross horizontal wells and completed 23 operated horizontal wells with an average of two completion crews. Operated completions consisted of 14 Lower Spraberry wells, six Wolfcamp A wells, two Middle Spraberry wells and one Wolfcamp B well. In January 2017, Diamondback added a sixth operated horizontal rig to begin development on the Company's previously acquired Southern Delaware Basin acreage. The Company anticipates closing its previously announced acquisition of leasehold interests and related assets from Brigham Resources at the end of February. Subsequent to the transaction close, Diamondback plans to operate two additional rigs in the Southern Delaware Basin.

Diamondback
continues to decrease drilling times, lower costs and achieve new Company records. During the fourth quarter of 2016, Diamondback drilled an 8,200 foot lateral well in Glasscock County in less than nine days from spud to total depth, a new record for the Company. Diamondback also drilled a 13,500 foot lateral in Midland County in 20.3 days, a new record for the Company.

Diamondback is increasing its pro forma full year 2017 production guidance to 69.0 to 76.0 Mboe/d, the midpoint of which is up over 65% from 2016 average daily production. The Company expects to complete 130 to 165 gross wells with an average lateral length of approximately 8,500 feet.

MIDLAND BASIN WELL RESULTS

In Howard County, Diamondback continues to see strong extended performance from its latest pad using a high-density near-wellbore completion design. These wells targeted the Lower Spraberry, Wolfcamp A and Wolfcamp B with an average completed lateral length of 9,725 feet. The Reed 1A 1WA and the Reed 1A 1WB achieved respective peak 30-day 2-stream initial production ("IP") rates of 1,978 boe/d (89% oil) and 1,605 boe/d (90% oil). After producing over 100,000 boe in 125 days, the Reed 1A 1LS well continues to produce over 1,100 boe/d (89% oil).

In Glasscock County,
Diamondback recently completed a two-well Wolfcamp A pad with an average lateral of 10,660 feet. The Ray 3427 A 4WA and Ray 3427 B 5WA achieved an average 30-day IP rate of 1,378 boe/d (85% oil) per well. After producing an average of 85 Mboe in 80 days, both wells are now producing over 1,400 boe/d (83% oil) on pump. Additionally, the Company recently completed its second and third Lower Spraberry wells in Glasscock County. These wells were completed with an average lateral of 10,423 feet and are currently in the early stages of flowback.

In Andrews County, Diamondback recently completed two Lower Spraberry wells with an average lateral of 10,000 feet and a high-density near-wellbore design. These wells
have achieved an average peak 15-day IP rate of 1,564 boe/d (89% oil) per well.

FINANCIAL HIGHLIGHTS

Diamondback's fourth quarter 2016 net income was $26 million, or $0.32 per diluted share. Adjusted net income (a non-GAAP financial measure as defined and reconciled below) was $72 million, or $0.90 per share.

Fourth quarter 2016 Adjusted EBITDA (as defined and reconciled below) was $138 million, up 35% from $102 million in Q3 2016. Fourth quarter 2016 revenues were $185 million, up 30% from $142 million in Q3 2016.

Diamondback's cash operating costs for the fourth
quarter of 2016 were $8.48 per boe, including lease operating expenses ("LOE") of $4.89 per boe and cash general and administrative expenses of $0.92 per boe. Total LOE expenses of $82.4 million for the full year 2016 was essentially flat versus 2015, despite production increasing 30% over the same period.

As of December 31, 2016, Diamondback had $1,667 million in cash and an undrawn $500 million credit facility. During the fourth quarter of 2016, Diamondback spent approximately $104 million on drilling and completion, $10 million on infrastructure and $8 million on non-operated properties. Additionally, the Company spent $87 million on acquisitions during the fourth quarter of 2016, including
$68 million attributable to Viper.

On October 20, 2016, Diamondback priced $500 million of 4.75% Senior Notes due 2024, with proceeds used primarily to repurchase the Company's prior outstanding 7.625% Senior Notes due 2021. On December 15, 2016, the Company priced $500 million of 5.375% Senior Notes due 2025, with proceeds to be used, along with proceeds from Diamondback's recent common equity offering, to fund a portion of the pending Brigham Resources acquisition.

RESERVES

Ryder Scott Company, L.P. prepared estimates of Diamondback's proved reserves as of December 31, 2016. Reference prices of
$42.75 per barrel of oil, $2.49 per MMbtu of natural gas and $19.97 per barrel of natural gas liquids were used in accordance with applicable rules of the Securities and Exchange Commission. Realized prices with applicable differentials were $39.94 per barrel of oil, $1.36 per Mcf of natural gas and $12.91 per barrel of natural gas liquids.

Proved reserves at year-end 2016 of 205.5 MMboe represent a 31% increase over year-end 2015 reserves. Proved developed reserves increased by 29% to 119.1 MMboe (58% of total proved reserves) as of December 31, 2016, reflecting the continued development of the Company's horizontal well inventory. Crude oil represents 68% of Diamondback's total proved reserves.

Net proved reserve additions of 64.3
MMboe resulted in a reserve replacement ratio of 409% (defined as the sum of extensions, discoveries, revisions and purchases, divided by annual production). The organic reserve replacement ratio was 380% (defined as the sum of extensions, discoveries and revisions, divided by annual production).

Purchases of reserves came primarily from the acquisition of working interest acreage in Reeves and Ward counties, which contributed 56% of the total purchased reserves. Mineral interest purchases by Viper contributed 37% of the total and the remaining purchases were bolt on acquisitions of working interest acreage. Extensions totaling 79.8 MMboe of reserves occurred from continued development of the Company's properties in the northwest
Midland Basin and the initial development of Diamondback's properties in Howard and Glasscock counties. Development occurred in the Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B horizons. Proved developed producing extensions accounted for approximately 50% of the extension reserves and were the result of 59 wells in which the Company also owns a working interest. It also includes Diamondback's mineral interests in 33 wells, 30 of which Diamondback has a working interest. Approximately 50% of the extension reserves are from 51 proved undeveloped locations in which the Company has a working interest. Reserves also include Diamondback's mineral interests in 32 locations, 30 of which the Company also owns a working
interest. Total downward revisions of 20.1 MMboe include 11.2 MMboe of pricing related revisions.

Oil (Bbls)

Liquids (Bbls)

Gas (Mcf)

BOE

Proved Reserves As of December 31, 2015

105,978,711

26,004,144

149,502,744

156,899,979

Extensions and discoveries

55,069,092

13,962,103

64,758,390

79,824,260

Revisions of previous estimates

(12,482,657

)

(1,887,643

)

(34,518,746

)

(20,123,424

)

Purchase of
reserves in place

2,170,774

1,454,836

5,582,053

4,555,952

Production

(11,561,920

)

(2,399,440

)

(10,428,441

)

(15,699,434

)

Proved Reserves As of December 31, 2016

139,174,000

37,134,000

174,896,000

205,457,333

Diamondback's exploration and development costs in 2016 were $376.7 million. Proved developed F&D costs were $7.26/boe. PD F&D costs are defined as exploration and development costs divided by the sum of reserves associated with transfers from proved undeveloped reserves at year end 2015
including any associated revisions in 2016 and extensions and discoveries placed on production during 2016. Drill bit F&D costs were $6.31/boe including the effects of all revisions including pricing revisions. Drill bit F&D costs are defined as the exploration and development costs divided by the sum of extensions, discoveries and revisions.

(in thousands)

Year Ended December 31,

2016

2015

2014

Acquisition costs

Proved properties

$

72,044

$

64,340

$

302,234

Unproved properties

752,117

448,638

601,188

Development costs

47,575

42,749

86,097

Exploration costs

329,122

319,102

475,756

Capitalized asset retirement costs

4,030

3,458

4,962

Total

$

1,204,888

$

878,287

$

1,470,237

FULL YEAR 2017 GUIDANCE

Below is Diamondback's full year 2017 guidance, which has been updated to reflect higher production, an increased completion cadence and detailed expense guidance. To account for the increased activity and the closing of the pending Brigham Resources
acquisition, the Company has increased its 2017 capital expenditure guidance for drilling, completion and infrastructure to $800.0 million to $1.0 billion, including $75 million of one time capital expenditures for oil and natural gas gathering systems in the Southern Delaware Basin.

2017 Guidance

Diamondback Energy, Inc.

Viper Energy Partners LP

Total Net Production - MBoe/d

69.0 - 76.0

8.0 - 8.5

Unit costs ($/boe)

Lease operating expenses, including workovers

$4.75 - $5.75

n/a

Gathering & Transportation

$0.50 - $1.00

$0.25 - $0.50

G&A

Cash G&A

$1.00 - $2.00

$0.50 - $1.50

Non-cash equity-based compensation

$1.50 - $2.50

$2.00 - $3.00

DD&A

$9.00 - $11.00

$8.00 - $10.00

Interest expense (net of interest income)

$2.50 - $3.50

Production and ad valorem taxes (% of revenue)(a)

7.0%

7.0%

($ - million)

Gross horizontal well costs - Midland Basin(b)

$5.0 - $5.5

n/a

Gross horizontal well costs - Delaware Basin(b)

$6.0 - $8.0

n/a

Horizontal wells completed (net)

130 - 165 (110 - 140)

n/a

Capital Budget ($ - million)

Horizontal drilling and completion

$650 - $825

n/a

Infrastructure

$150 - $175

n/a

2017 Capital Spend

$800 - $1,000

n/a

(a) Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and NGLs and ad valorem taxes.

(b) Assumes a 7,500' average lateral length.

CONFERENCE CALL

Diamondback will host a conference
call and webcast for investors and analysts to discuss its financial and operating results for the fourth quarter and full year of 2016 on Wednesday, February 15, 2017 at 8:30 a.m. CT. Participants should call (877) 440-7573 (United States/Canada) or (253) 237-1144 (International) and use the confirmation code 66899658. A telephonic replay will be available from 11:30 a.m. CT on Wednesday, February 15, 2017 through Wednesday, February 22, 2017 at 11:30 a.m. CT. To access the replay, call (855) 859-2056 (United States/Canada) or (404) 537-3406 (International) and enter confirmation code
66899658. A live broadcast of the earnings conference call will also be available via the internet at www.diamondbackenergy.com under the "Investor Relations" section of the site. A replay will also be available on the website following the call.

About Diamondback Energy, Inc.

Diamondback is an independent oil and natural gas Company headquartered in Midland, Texas focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.
Diamondback's activities are primarily focused on the horizontal exploitation of multiple intervals within the Wolfcamp, Spraberry, Clearfork, Bone Spring and Cline formations.

Forward Looking Statements

This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that Diamondback assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements, including specifically the statements regarding the pending acquisition discussed above. The forward-looking statements are based on management's current beliefs, based on currently available information, as to the outcome and timing of future events. These forward-looking statements involve certain risks and
uncertainties that could cause the results to differ materially from those expected by the management of Diamondback. Information concerning these risks and other factors can be found in Diamondback's filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the Securities and Exchange Commission's web site at http://www.sec.gov. Diamondback undertakes no obligation to update or revise any forward-looking statement.

Diamondback Energy, Inc.

Consolidated Statements of Operations

(unaudited, in thousands, except share amounts and per share data)

Three Months EndedDecember 31,

Twelve Months EndedDecember 31,

2016

2015

2016

2015

Revenues

Oil, natural gas liquids and natural gas

$

185,012

$

114,323

$

527,107

$

446,733

Operating Expenses

Lease operating expenses

23,348

17,508

82,428

82,625

Production and ad valorem taxes

9,212

7,954

34,456

32,990

Gathering and transportation

3,542

1,748

11,606

6,091

Depreciation, depletion and amortization

51,329

48,549

178,015

217,697

Impairment of oil and natural gas properties

—

217,610

245,536

814,798

General and administrative expenses

10,208

8,522

42,619

31,968

Asset retirement obligation accretion expense

294

245

1,064

833

Total expenses

97,933

302,136

595,724

1,187,002

Income (loss) from operations

87,079

(187,813

)

(68,617

)

(740,269

)

Interest income (expense)

(10,418

)

(10,106

)

(40,684

)

(41,510

)

Other income

1,417

(520

)

3,064

728

Gain (loss) on derivative instruments, net

(16,680

)

5,117

(25,345

)

31,951

Loss on extinguishment of debt

(33,134

)

—

(33,134

)

—

Total other
income (expense), net

(58,815

)

(5,509

)

(96,099

)

(8,831

)

Income (loss) before income taxes

28,264

(193,322

)

(164,716

)

(749,100

)

Provision for (benefit from) income taxes

(176

)

(6,487

)

192

(201,310

)

Net income (loss)

28,440

(186,835

)

(164,908

)

(547,790

)

Net income attributable to non-controlling interest

2,842

574

126

2,838

Net income (loss) attributable to Diamondback Energy, Inc.

$

25,598

$

(187,409

)

$

(165,034

)

$

(550,628

)

Earnings per common share:

Basic

$

0.32

$

(2.80

)

$

(2.20

)

$

(8.74

)

Diluted

$

0.32

$

(2.80

)

$

(2.20

)

$

(8.74

)

Weighted average common shares outstanding:

Basic

80,315

66,850

75,077

63,019

Diluted

80,510

66,850

75,077

63,019

Diamondback Energy, Inc.

Selected Operating Data

(unaudited)

Three Months Ended December 31,

Twelve Months Ended December 31,

2016

2015

2016

2015

Production Data:

Oil (MBbl)

3,507

2,641

11,562

9,081

Natural gas (MMcf)

3,172

2,407

10,728

7,931

Natural gas liquids (MBbls)

742

418

2,399

1,678

Oil Equivalents (MBOE)(1)(2)

4,778

3,460

15,749

12,081

Average daily production (BOE/d)(2)

51,934

37,614

43,031

33,098

% Oil

73

%

76

%

73

%

75

%

Average sales prices:

Oil, realized ($/Bbl)

$

46.72

$

39.32

$

40.70

$

44.68

Natural gas realized ($/Mcf)

2.53

2.14

2.10

2.47

Natural gas liquids ($/Bbl)

17.70

12.68

14.20

12.77

Average price realized ($/BOE)

38.72

33.04

33.47

36.98

Oil, hedged ($/Bbl)(3)

45.86

54.66

40.80

60.63

Average price, hedged ($/BOE)(3)

38.09

44.74

33.54

48.97

Average Costs per BOE:

Lease operating expense

$

4.89

$

5.06

$

5.23

$

6.84

Production and ad valorem taxes

1.93

2.30

2.19

2.73

Gathering and transportation expense

0.74

0.51

0.74

0.50

General and administrative - cash component

0.92

1.06

1.03

1.11

Total operating expense - cash

$

8.48

$

8.93

$

9.19

$

11.18

General and administrative - non-cash component

$

1.22

$

1.40

$

1.68

$

1.54

Depreciation, depletion, and amortization

10.74

14.03

11.30

18.02

Interest expense

2.18

2.92

2.58

3.44

(1

)

Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2

)

The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above.

(3

)

Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation ofsuch effects includes realized gains and losses on cash settlements for commodity derivatives, which we do not designatefor hedge accounting.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDA as net income (loss) plus non-cash loss on derivative
instruments, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity-based compensation expense, capitalized equity-based compensation expense, asset retirement obligation accretion expense, loss on extinguishment of debt and income tax (benefit) provision. Adjusted EBITDA is not a measure of net income (loss) as determined by United States' generally accepted accounting principles ("GAAP"). Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate the Company's operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. The Company adds the items listed above to net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within its industry
depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of the Company's operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Adjusted net income is a non-GAAP financial measure equal to net income (loss) attributable to Diamondback Energy, Inc. plus non-cash (gain) loss on derivative instruments, net, (gain) loss on the sale of
assets, net, impairment of oil and gas properties, loss on extinguishment of debt and related income tax adjustments. The Company's computations of Adjusted EBITDA and adjusted net income may not be comparable to other similarly titled measures of other companies or to such measure in our credit facility or any of our other contracts.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income.

Diamondback Energy, Inc.

Reconciliation of Adjusted EBITDA to Net Income

(unaudited, in thousands)

Three Months EndedDecember 31,

Twelve Months EndedDecember 31,

2016

2015

2016

2015

Net income (loss)

$

28,440

$

(186,835

)

$

(164,908

)

$

(547,790

)

Non-cash loss on derivative instruments

13,664

35,386

26,522

112,918

Interest expense

10,418

10,106

40,684

41,510

Depreciation, depletion and amortization

51,329

48,549

178,015

217,697

Impairment of oil and natural gas properties

—

217,610

245,536

814,798

Non-cash equity-based compensation expense

7,364

5,788

33,532

24,572

Capitalized equity-based compensation expense

(1,554

)

(918

)

(7,079

)

(6,043

)

Asset retirement obligation accretion expense

294

245

1,064

833

Loss on extinguishment of debt

33,134

—

33,134

—

Income tax (benefit) provision

(176

)

(6,487

)

192

(201,310

)

Consolidated Adjusted
EBITDA

$

142,913

$

123,444

$

386,692

$

457,185

EBITDA attributable to noncontrolling interest

(4,605

)

(2,154

)

843

(7,940

)

Adjusted EBITDA attributable to Diamondback Energy, Inc.

$

138,308

$

121,290

$

387,535

$

449,245

Adjusted net income is a performance
measure used by management to evaluate performance, prior to non-cash losses on derivative instruments, (gain) on sale of assets, net, impairment of oil and gas properties and related income tax adjustments.

The following table presents a reconciliation of adjusted net income to net income:

Diamondback Energy, Inc.

Adjusted Net Income

(unaudited, in thousands, except share amounts and per share data)

Three Months EndedDecember 31,

Twelve Months EndedDecember 31,

2016

2015

2016

2015

Net income (loss) attributable to Diamondback Energy, Inc.

$

25,598

$

(187,409

)

$

(165,034

)

$

(550,628

)

Plus:

Non-cash loss on derivative instruments

13,664

35,386

26,522

112,918

(Gain) loss on sale of assets, net

(24

)

759

(61

)

668

Impairment of oil and gas properties*

—

217,213

246,087

814,400

Loss on extinguishment of debt

33,134

—

33,134

—

Income tax adjustment for above items**

—

(27,758

)

—

(263,878

)

Adjusted net income attributable to Diamondback Energy, Inc.

$

72,372

$

38,191

$

140,648

$

113,480

Adjusted net income per common share:

Basic

$

0.90

$

0.57

$

1.87

$

1.80

Diluted

$

0.90

$

0.57

$

1.87

$

1.80

Weighted average common shares outstanding:

Basic

80,315

66,850

75,077

63,019

Diluted

80,510

66,850

75,077

63,019

*Impairment has been adjusted for Viper's noncontrolling interest.**The tax impact is computed utilizing the Company's effective federal and state income tax rates. The income tax rate for the three months ended December 31, 2016 was approximately 0% while it was approximately 35% for the three months ended December 31, 2015.

PV-10

PV-10 is the Company's estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." The Company believes PV-10 to be an important measure for evaluating the relative significance of its oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when
estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. The Company believes that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.

The following table reconciles PV-10 to the Company's standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

(in
thousands)

December 31, 2016

PV-10

$

1,741,868

Less income taxes:

Undiscounted future income taxes

(75,595

)

10% discount factor

(45,140

)

Future discounted income taxes

(30,455

)

Standardized measure of discounted future net cash flows

$

1,711,413

Derivatives

As of the filing
date, the Company had the following outstanding derivative contracts. The Company's derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing. When aggregating multiple contracts, the weighted average contract price is disclosed.